IGCC Plant — Bituminous Coal GE Energy IGCC

GE Energy IGCC Plant

Plant Overview

This analysis is based on a 640 MWe (net power 

output) Integrated Gasifi cation Combined-Cycle 

(IGCC) plant using GE Energy (GEE) radiant-only 

gasifi cation technology, located at a greenfi eld site 

in the midwestern United States. The radiant-only 

confi guration consists of a radiant synthesis gas 

cooler followed by a water quench. Two pressurized, 

slurry-fed, entrained fl ow gasifi cation trains feed two 

advanced F-Class combustion turbines. Two heat 

recovery steam generators (HRSGs) and one steam 

turbine provide additional power. The combination process and heat and mass balance diagram for the GEE 

IGCC plant is shown in Figure 1. The primary fuel is an Illinois No. 6 bituminous coal with a higher heating value 

(HHV) of 11,666 Btu/lb. The capacity factor (CF) for the plant is 80 percent without sparing of major train 

components. A summary of plant performance data for the GEE IGCC plant is presented in Table 1. 

Figure 1. Process Flow Diagram 

GEE IGCC

Table 1. Plant Performance Summary

Plant Type GEE IGCC

Carbon capture No

Net power output (kWe) 640,250

Net plant HHV effi ciency (%) 38.2

Primary fuel (type) Illinois No. 6 coal

Levelized cost-of-electricity 

(mills/kWh) @ 80% capacity factor 

78.0

Note: Diagram is provided for general reference of major fl ows only. For complete fl ow information, please refer to the fi nal report.
IGCC Plant — Bituminous Coal GE Energy IGCC

B_IG_GEE–2

Technical Description

The plant uses an improved version of the GEE gasifi cation 

technology (formerly licensed by Chevron Corp. and 

predecessor company Texaco Inc.), which is currently in 

operation at the 250 MWe Tampa Electric IGCC plant in 

Polk County, FL. All technology selected in the plant design 

is assumed to be available to facilitate a 2010 startup date for 

anewly constructed plant. A summary of performance for an 

advanced F-Class combustion turbine for the GEE IGCC plant 

is presented in Table 2.

Two gasifi cation trains process a total of 5,876 tons of coal per day. A slurry (63 percent by weight coal) is 

transferred from the slurry storage tank to the gasifi er with a high-pressure pump. Oxygen (O2

) is produced 

in a cryogenic air separation unit. The coal slurry and O2

 react in the gasifi er at about 5.6 MPa (815 psia) at a 

high temperature (in excess of 1,316°C [2,400°F]) to produce syngas. Hot syngas and molten solids from the 

reactor fl ow downward into a radiant heat exchanger, where the syngas is cooled to 593°C (1,100°F) and the 

ash solidifi es. Raw syngas continues downward into a quench system where most of the particulate matter (PM) 

is removed and then into the syngas scrubber where most of the remaining entrained solids are removed along 

with ammonia. Slag captured by the quench system is recovered in a slag recovery unit. The gas goes through 

a series of additional gas coolers and cleanup processes, including a carbonyl sulfi de hydrolysis reactor, a carbon 

bed for mercury (Hg) removal, and a Selexol-based acid gas removal (AGR) plant. 

A Brayton cycle, fueled by syngas, is used in conjunction with a conventional subcritical steam Rankine cycle 

for combined-cycle power generation. Compressed nitrogen from the air separation unit is used for syngas 

dilution, which aids in minimizing the formation of nitrogen oxides (NOx) during combustion in the gas turbine 

burner section. The limiting factor that determines the use of a subcritical steam cycle is the maximum design 

pressure of 12.4 MPa (1,800 psig), which can be tolerated 

in the GEE radiant cooler. The two cycles are integrated by 

generation of steam in the HRSGs, by feedwater heating in 

the HRSGs, and by heat recovery from the IGCC process 

(radiant syngas cooler). The HRSG/steam turbine cycle is 

12.4 MPa/566°C/566°C (1,800 psig/1,050°F/1,050°F). The 

plant produces a net output of 640 MWe. The summary 

of plant electrical generation performance is presented in 

Table 3. This confi guration results in a net plant effi ciency 

of 38.2 percent (HHV basis), or a net HHV heat rate of 

8,922 Btu/kWh.

Environmental Performance

The environmental specifi cations for a greenfi eld IGCC plant are based on the Electric Power Research Institute 

CoalFleet User Design Basis for Coal-Based IGCC Plants specifi cation. Low sulfur dioxide (SO2) emissions (less 

than 4 ppmv in the fl ue gas) are achieved by capture of the sulfur in the Selexol AGR process, which removes 

over 99 percent of the sulfur in the fuel gas. The resulting hydrogen sulfi de-rich regeneration gas from the AGR 

system is fed to a Claus plant, producing elemental sulfur. Nitrogen oxides emissions are limited by nitrogen 

dilution in the gas turbine combustor to 15 ppmvd (as nitrogen oxide at 15 percent O2

). Filterable PM discharge 

to the atmosphere is limited by the use of the syngas quench in addition to the syngas scrubber and the gaswashing effect of the AGR absorber. Ninety-fi ve percent of the Hg is captured from the syngas by an activated 

carbon bed.

Table 2. Advanced Gas Turbine Performance1

Advanced F-Class

Net output, MWe 185

Pressure ratio 18.5

Airfl ow, kg/s (lb/s) 431 (950)

Firing temperature°C (°F) >1,371 (>2,500)

1

At International Standards Organization conditions 

fi ring natural gas. Performance information for syngas 

fi ring is not available.

Table 3. Plant Electrical Generation

Electrical 

Summary

Advanced gas turbine x 2, MWe 464.3

Steam turbine, MWe 298.9

Sweet gas expander, MWe 7.1

Gross power output, MWe 770.3

Auxiliary power requirement, MWe (130.1)

Net power output, MWe 640.2
IGCC Plant — Bituminous Coal GE Energy IGCC

B_IG_GEE–3

A summary of the resulting air emissions for the GEE IGCC plant is presented in Table 4.

Cost Estimation 

Plant size, primary/secondary fuel type, construction time, total plant 

cost (TPC) basis year, plant CF, plant heat rate, fuel cost, plant book 

life, and plant in-service date were used to develop capital cost, 

production cost, and levelized cost-of-electricity (LCOE) estimates. 

Costs for the plant were based on adjusted vendor-furnished and 

actual cost data from recent design/build projects. Values for fi nancial 

assumptions and a cost summary are shown in Table 5. 

Project contingencies were added to each case to cover project 

uncertainty and the cost of any additional equipment that could 

result from detailed design. The project contingencies represent 

costs that are expected to occur. Project contingency was 

13.3 percent of the GEE IGCC case TPC.

Process contingency is intended to compensate for uncertainties 

arising as a result of the state of technology development. Process 

contingencies represent 2.5 percent of the GEE IGCC case TPC and 

have been applied to the estimates as follows:

Slurry Prep and Feed – 5 percent on GE IGCC cases.

Gasifi ers and Syngas Coolers – 15 percent on all IGCC 

cases. 

Mercury Removal – 5 percent on all IGCC cases. 

Combustion Turbine Generator – 5 percent on all IGCC cases without CCS.

Instrumentation and Controls – 5 percent on all IGCC cases.

This study assumes that each new plant would be dispatched any time it is available and would be capable of 

generating maximum capacity when online. Therefore, CF is assumed to equal availability and is 80 percent for 

IGCC cases. 

The 640 MWe (net) GEE IGCC plant was projected to have a TPC of $1,813/kWe, resulting in a 20-year LCOE 

of 78 mills/kWh.

•

•

•

•

•

Table 4. Air Emissions Summary 

@ 80% Capacity Factor

Pollutant GEE IGCC 

Without 

CSS

CO2

• tons/year 3,937,728

• lb/MMBtu 197

• cost of CO2 avoided N/A

SO2

• tons/year 254

• lb/MMBtu 0.0127

NOx

• tons/year 1,096

• lb/MMBtu 0.055

PM (fi lterable)

• tons/year 142

• lb/MMBtu 0.0071

Hg

• tons/year 0.011

• lb/TBtu 0.571
IGCC Plant — Bituminous Coal GE Energy IGCC

B_IG_GEE–4

Reference: Cost and Performance Baseline for Fossil Energy Plants, Vol. 1, DOE/NETL-2007/1281, May 2007. 

B_IG_GEE_051507

Julianne M. Klara

Senior Analyst

National Energy Technology Laboratory

626 Cochrans Mill Road

P.O. Box 10940

Pittsburgh, PA 15236

412-386-6089

julianne.klara@netl.doe.gov

John G. Wimer

Systems Analysis Team Lead

National Energy Technology Laboratory

3610 Collins Ferry Road

P. O. Box 880

Morgantown, WV 26507

304-285-4124

john.wimer@netl.doe.gov

Contacts

Table 5. Major Financial Assumptions and Resulting Cost Summary1

Major Assumptions

Case: 1x640 MWe net GEE IGCC

Plant Size: 640.3 (MWe, net) Heat Rate: 8,922 (Btu/kWh)

Primary/Secondary Fuel (type): Illinois #6 Coal Fuel Cost: 1.80 ($/MMBtu)

Construction Duration: 3 (years) Plant Life: 30 (years)

Total Plant Cost2

 Year: 2007 (January) Plant in Service: 2010 (January)

Capacity Factor: 80 (%) Capital Charge Factor: 17.5 (%)

Resulting Capital Investment (Levelized 2007 dollars) Mills/kWh

Total Plant Cost 43.3

Resulting Operating Costs (Levelized 2007 dollars)3 Mills/kWh

Fixed Operating Cost 5.8

Variable Operating Cost 7.5

Resulting Fuel Cost (Levelized 2007 dollars) @ $1.80 / MMBtu Mills/kWh

19.4

Total Levelized Busbar Cost of Power (2007 dollars) Mills/kWh

78.0

1

Costs shown can vary ± 30%.

2

Total plant cost includes all equipment (complete with initial chemical and catalyst loadings), materials, labor (direct and indirect), engineering and construction management, and contingencies (process and project). Owner’s costs are not included.

3

No credit taken for by-product sales.